Method for fracking subterranean geological formation with surfactant-containing fluid

ABSTRACT

A surfactant of formula (I)wherein each of R1 and R2 are independently a hydrogen, an optionally substituted alkyl, an optionally substituted cycloalkyl, or an optionally substituted arylalkyl, R3 and R4 are independently an optionally substituted alkyl, an optionally substituted cycloalkyl, or an optionally substituted arylalkyl, x is an integer in a range of 2-8, y is an integer in a range of 1-15, z is an integer in a range of 4-10, n is an integer in a range of 2-5, and A is one of a carboxybetaine group, a sulfobetaine group, or a hydroxy sulfobetaine group. An oil and gas well servicing fluid containing the surfactant and methods of servicing an oil and gas well are also described.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a Continuation of U.S. application Ser. No.16/749,342, now allowed, having a filing date of Jan. 22, 2020 whichclaims benefit of priority to U.S. Provisional Application No.62/910,856 having a filing date of Oct. 4, 2019.

STATEMENT OF ACKNOWLEDGEMENT

This research was supported by the College of Petroleum Engineering &Geoscience, KFUPM through project no. SF-17003.

STATEMENT REGARDING PRIOR DISCLOSURE BY THE INVENTORS

Aspects of this technology are described in an article “Synthesis andphysicochemical investigation of betaine type polyoxyethylenezwitterionic surfactants containing different ionic headgroups”published in Journal of Molecular Structure, 2019, 1178, 83-88,available online on Oct. 5, 2018, which is incorporated herein byreference in its entirety.

BACKGROUND OF THE INVENTION Technical Field

The present disclosure relates to betaine-type surfactants containing anunsaturated fatty tail, servicing fluids made therefrom, and methods ofusing the surfactants in oil and gas well servicing operations.

Description of the Related Art

The “background” description provided herein is for the purpose ofgenerally presenting the context of the disclosure. Work of thepresently named inventors, to the extent it is described in thisbackground section, as well as aspects of the description which may nototherwise qualify as prior art at the time of filing, are neitherexpressly or impliedly admitted as prior art against the presentinvention.

Surfactants are composed of hydrophilic (the “head”) and hydrophobic(the “tail”) groups and are soluble in organic solvents and water. SeeA. H. Abbas, W. R. W. Sulaiman, M. Z. Jaafar, A. A. Olayink, S. S.Ebrahimi, A. Elrufai, Numerical study for continuous surfactant floodingconsidering adsorption in heterogeneous reservoir, Journal of King SaudUniversity-Engineering Sciences (2018), incorporated herein by referencein its entirety. They are known to reduce the surface tension andinterfacial tension (IFT) between crude oil and water, increase thecapillary number, alter the wettability of reservoir rocks towards morewater wet, ultimately enhancing the efficiency of oil production. See A.M. Howe, A. Clarke, J. Mitchell, J. Staniland, L. Hawkes, C. Whalan,Visualising surfactant enhanced oil recovery, Colloids and Surfaces A:Physicochemical and Engineering Aspects 480 (2015) 449-461, incorporatedherein by reference in its entirety. However, use of surfactants inupstream applications is challenging owing to poor thermal stability,poor solubility, and high adsorption of the surfactants on the formationrocks. See P. Raffa, A. A. Broekhuis, F. Picchioni, Polymericsurfactants for enhanced oil recovery: A review, Journal of PetroleumScience and Engineering 145 (2016) 723-733; N. Saxena, N. Pal, S. Dey,A. Mandal, Characterizations of surfactant synthesized from palm oil andits application in enhanced oil recovery, Journal of the TaiwanInstitute of Chemical Engineers 81 (2017) 343-355; N. Pal, N. Saxena, K.D. Laxmi, A. Mandal, Interfacial behaviour, wettability alteration andemulsification characteristics of a novel surfactant: Implications forenhanced oil recovery, Chem. Eng. Sci. (2018); and N. Pal, N. Saxena, A.Mandal, Studies on the physicochemical properties of synthesizedtailor-made gemini surfactants for application in enhanced oil recovery,J. Mol. Liq. (2018), each incorporated herein by reference in theirentirety.

Surfactants can be categorized as nonionic, zwitterionic, anionic, andcationic depending on the charge of the headgroup, which contributes tothe physicochemical properties of surfactants. See G. Wu, C. Yuan, X.Ji, H. Wang, S. Sun, S. Hu, Effects of head type on the stability ofgemini surfactant foam by molecular dynamics simulation, ChemicalPhysics Letters 682 (2017) 122-127, incorporated herein by reference inits entirety. The selection of a suitable class of surfactant largelydepends on the nature of reservoir rocks. See K. Ma, L. Cui, Y. Dong, T.Wang, C. Da, G. J. Hirasaki, S. L. Biswal, Adsorption of cationic andanionic surfactants on natural and synthetic carbonate materials,Journal of colloid and interface science 408 (2013) 164-172,incorporated herein by reference in its entirety. For instance, anionicsurfactants are typically preferred for sandstone rocks due to lowadsorption. See W. Kwok, R. Hayes, H. Nasr-El-Din, Modelling dynamicadsorption of an anionic surfactant on Berea sandstone with radial flow,Chemical engineering science 50(5) (1995) 769-783, incorporated hereinby reference in its entirety. Similarly, cationic surfactants are oftenapplied in carbonate reservoirs in order to avoid high adsorption. SeeS. S. Hussain, M. S. Kamal, Effect of large spacer on surface activity,thermal, and rheological properties of novel amido-amine cationic geminisurfactants, Journal of Molecular Liquids 242 (2017) 1131-1137,incorporated herein by reference in its entirety. Moreover, nonionicsurfactants are used to enhance salt tolerance, but they show higher IFTvalues compared to anionic surfactants.

Zwitterionic surfactants have gained considerable attention both in theacademic field and industry due to superior properties such as heatresistance, salt tolerance, excellent aqueous solubility, high foamstability, and good biodegradability. See S. j. Dong, Y. l. Li, Y. b.Song, L. f. Zhi, Synthesis, Characterization and Performance ofUnsaturated Long-Chain Carboxybetaine and Hydroxy Sulfobetaine, Journalof Surfactants and Detergents 16(4) (2013) 523-529, incorporated hereinby reference in its entirety. A number of zwitterionic surfactants havebeen devised for oilfield applications and the number continues toincrease. See A. Kumar, A. Mandal, Characterization of rock-fluid andfluid-fluid interactions in presence of a family of synthesizedzwitterionic surfactants for application in enhanced oil recovery,Colloids and Surfaces A: Physicochemical and Engineering Aspects 549(2018) 1-12; S. S. Hussain, M. S. Kamal, L. T. Fogang, Effect ofinternal olefin on the properties of betaine-type zwitterionicsurfactants for enhanced oil recovery, J. Mol. Liq. (2018); S. Chen, H.Liu, H. Sun, X. Yan, G. Wang, Y. Zhou, J. Zhang, Synthesis andphysiochemical performance evaluation of novel sulphobetainezwitterionic surfactants from lignin for enhanced oil recovery, Journalof Molecular Liquids 249 (2018) 73-82; and C. Da, S. Alzobaidi, G. Jian,L. Zhang, S. L. Biswal, G. J. Hirasaki, K. P. Johnston, Carbondioxide/water foams stabilized with a zwitterionic surfactant attemperatures up to 150° C. in high salinity brine, Journal of PetroleumScience and Engineering 166 (2018) 880-890, each incorporated herein byreference in their entirety.

The functionality and overall chemical structure of zwitterionicsurfactants plays a key role for selected oilfield applications. Forexample, the addition of a carboxylate head group may enhance the watersolubility of the surfactant, and the introduction of a hydroxysulfobetaine head group increases hydrophilicity. See Y. Wang, Y. Zhang,X. Liu, J. Wang, L. Wei, Y. Feng, Effect of a Hydrophilic Head Group onKrafft Temperature, Surface Activities and Rheological Behaviors ofErucyl Amidobetaines, J. Surfactants. Deterg. 17(2) (2014) 295-301,incorporated herein by reference in its entirety. However, the increasein chain length lowers the water solubility of the surfactant. Longhydrophobic tails (≥C18) have shown the ability to form worm-likemicelles, but their poor water solubility has limited surfactants tohydrophobic tails made from less than 18 carbon atoms. See S. ShakilHussain, M. A. Animashaun, M. S. Kamal, N. Ullah, I. A. Hussein, A. S.Sultan, Synthesis, characterization and surface properties ofamidosulfobetaine surfactants bearing odd-number hydrophobic tail,Journal of Surfactants and Detergents 19(2) (2016) 413-420, incorporatedherein by reference in its entirety. This poor solubility may be atleast partially offset through the introduction of ethoxylated (EO)units, which may also improve thermal stability, and prevent the needfor co-solvents such as alcohol to attain ultralow IFT values. See B.Barry, R. Wilson, CMC, counterion binding and thermodynamics ofethoxylated anionic and cationic surfactants, Colloid and PolymerScience 256(3) (1978) 251-260; C. Negin, S. Ali, Q. Xie, Most commonsurfactants employed in chemical enhanced oil recovery, Petroleum 3(2)(2017) 197-211, each incorporated herein by reference in its entirety.However, an improperly chosen degree of ethoxylation can lead to lowrecovery, high adsorption onto the reservoir rocks and/or possible rockdissolution resulting in formation damage. With so many competingissues, it is difficult to predict how a particular surfactant will fairin a specified oil field application/setting. Therefore, developingsurfactants that reduce the IFT between crude oil and water, arethermally stable under reservoir conditions, are soluble in highsalinity environments, and which provide low adsorption into formationrocks, remains a significant challenge.

In view of the forgoing, one objective of the present disclosure is toprovide betaine-type surfactants containing an unsaturated fatty tailwhich overcome these challenges. Another objective of the presentdisclosure is to provide servicing fluids containing these surfactantsfor use in servicing oil and gas wells.

BRIEF SUMMARY OF THE INVENTION

According to a first aspect, the present disclosure relates to asurfactant of formula (I)

-   -   wherein:    -   each of R₁ and R₂ are independently selected from the group        consisting of a hydrogen, an optionally substituted alkyl, an        optionally substituted cycloalkyl, and an optionally substituted        arylalkyl;    -   R₃ and R₄ are independently selected from the group consisting        of an optionally substituted alkyl, an optionally substituted        cycloalkyl, and an optionally substituted arylalkyl;    -   x is an integer in a range of 2-8;    -   y is an integer in a range of 1-15;    -   z is an integer in a range of 4-10;    -   n is an integer in a range of 2-5;    -   A is an anionic headgroup selected from the group consisting of

-   -   or a solvate, tautomer thereof, or stereoisomer thereof.

In some embodiments, each of R₁ and R₂ are independently a hydrogen, ora methyl.

In some embodiments, each of R₁ and R₂ are a hydrogen.

In some embodiments, R₃ and R₄ are independently selected from the groupconsisting of a methyl, an ethyl, and an isopropyl.

In some embodiments, R₃ and R₄ are a methyl.

In some embodiments, x is an integer in a range of 4-6.

In some embodiments, y is an integer in a range of 7-10.

In some embodiments, z is 6.

In some embodiments, n is 3.

In some embodiments, A is

In some embodiments, A is

In some embodiments, A is

In some embodiments, the carbon-carbon double bond present in formula(I) is in a cis-double bond configuration.

In some embodiments, the surfactant is selected from the groupconsisting of

-   -   wherein in each structure y is 8 or 9.

In some embodiments, the surfactant has a critical micelle concentrationin water at 30 to 60° C. of 3×10⁻⁵ to 5×10⁻⁴ M, and a surface tension atthe critical micelle concentration of 31-39 mN/m.

According to a second aspect, the present disclosure relates to an oiland gas well servicing fluid, containing an aqueous base fluid and thesurfactant of formula (I).

In some embodiments, the oil and gas well servicing fluid has a totaldissolved solids content of 50,000-350,000 ppm.

In some embodiments, the surfactant is present in an amount of 0.001-15wt. % relative to a total weight of the oil and gas well servicingfluid.

According to a third aspect, the present disclosure relates to a methodof servicing an oil and gas well during fracking, drilling, completion,and/or workover whereby the oil and gas well servicing fluid is injectedinto the oil and gas well.

In some embodiments, the oil and gas well has a temperature of 30-150°C.

The foregoing paragraphs have been provided by way of generalintroduction, and are not intended to limit the scope of the followingclaims. The described embodiments, together with further advantages,will be best understood by reference to the following detaileddescription taken in conjunction with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete appreciation of the disclosure and many of the attendantadvantages thereof will be readily obtained as the same becomes betterunderstood by reference to the following detailed description whenconsidered in connection with the accompanying drawings, wherein:

FIG. 1 illustrates the ¹H NMR spectra of OPAS;

FIG. 2 illustrates the ¹³C NMR spectra of OPAS;

FIG. 3 is a graph illustrating the FT-IR spectra of OPAS;

FIG. 4 is a snapshot of surfactant solutions (OPAC, OPAH, and OPAS) inseawater for 90 days at 90° C., showing no signs of precipitation orphase separation;

FIG. 5 is a snapshot of surfactant solutions (OPAC, OPAH, and OPAS) information water for 90 days at 90° C., showing no signs of precipitationor phase separation;

FIG. 6 is a TGA graph of OPAC, OPAS, and OPAH;

FIG. 7 is a graph illustrating the surface properties of OPAC at variousconcentrations at 30° C. and 60° C. in water;

FIG. 8 is a graph illustrating the surface properties of OPAS at variousconcentrations at 30° C. and 60° C. in water;

FIG. 9 is a graph illustrating the surface properties of OPAH at variousconcentrations at 30° C. and 60° C. in water; and

FIG. 10 illustrates the synthesis of betaine type polyoxyethylenezwitterionic surfactants (OPAC, OPAS, and OPAH) containing differentionic headgroups.

DETAILED DESCRIPTION OF THE EMBODIMENTS

Embodiments of the present disclosure will now be described more fullyhereinafter with reference to the accompanying drawings, in which some,but not all embodiments of the disclosure are shown.

Definitions

As used herein, the words “a” and “an” and the like carry the meaning of“one or more”. Within the description of this disclosure, where anumerical limit or range is stated, the endpoints are included unlessstated otherwise. Also, all values and subranges within a numericallimit or range are specifically included as if explicitly written out.

The phrase “substantially free”, unless otherwise specified, describes aparticular component being present in an amount of less than about 1 wt.%, preferably less than about 0.5 wt. %, more preferably less than about0.1 wt. %, even more preferably less than about 0.05 wt. %, yet evenmore preferably 0 wt. %, relative to a total weight of the compositionbeing discussed.

As used herein, the terms “optional” or “optionally” means that thesubsequently described event(s) can or cannot occur or the subsequentlydescribed component(s) may or may not be present (e.g., 0 wt. %).

As used herein, the terms “compound”, “surfactant”, and “product” areused interchangeably, and are intended to refer to a chemical entity,whether in the solid, liquid or gaseous phase, and whether in a crudemixture or purified and isolated.

As used herein, the term “solvate” refers to a physical association of acompound of this disclosure with one or more solvent molecules, whetherorganic or inorganic. This physical association includes hydrogenbonding. In certain instances, the solvate will be capable of isolation,for example when one or more solvent molecules are incorporated in thecrystal lattice of the crystalline solid. The solvent molecules in thesolvate may be present in a regular arrangement and/or a non-orderedarrangement. The solvate may comprise either a stoichiometric ornonstoichiometric amount of the solvent molecules. Solvate encompassesboth solution phase and isolable solvates. Exemplary solvents include,but are not limited to, water, methanol, ethanol, n-propanol,isopropanol, n-butanol, isobutanol, tert-butanol, ethyl acetate andother lower alkanols, glycerine, acetone, dichloromethane (DCM),dimethyl sulfoxide (DMSO), dimethyl acetate (DMA), dimethylformamide(DMF), isopropyl ether, acetonitrile, toluene, N-methylpyrrolidone(NMP), tetrahydrofuran (THF), tetrahydropyran, other cyclic mono-, di-and tri-ethers, polyalkylene glycols (e.g. polyethylene glycol,polypropylene glycol, propylene glycol), and mixtures thereof insuitable proportions. Exemplary solvates include, but are not limitedto, hydrates, ethanolates, methanolates, isopropanolates and mixturesthereof. Methods of solvation are generally known to those of ordinaryskill in the art.

Throughout the specification and the appended claims, a given chemicalformula or name shall encompass all stereo and optical isomers andracemates thereof where such isomers exist. Unless otherwise indicated,all chiral (enantiomeric and diastereomeric) and racemic forms arewithin the scope of the disclosure. Many geometric isomers of C═C doublebonds, C═N double bonds, ring systems, and the like can also be presentin the compounds, and all such stable isomers are contemplated in thepresent disclosure. Cis- and trans- (or Z- and E-) geometric isomers ofthe compounds of the present disclosure, which may be denoted by usingundefined bond geometries, e.g.,

are described and may be isolated as a mixture of isomers or asseparated isomeric forms. The present compounds can be isolated inoptically active or racemic forms. Optically active forms may beprepared by resolution of racemic forms or by synthesis from opticallyactive starting materials. All processes used to prepare compounds ofthe present disclosure and intermediates made therein are considered tobe part of the present disclosure. When enantiomeric or diastereomericproducts are prepared, they may be separated by conventional methods,for example, by chromatography, fractional crystallization, or throughthe use of a chiral agent. Depending on the process conditions the endproducts of the present disclosure are obtained either in free (neutral)or salt form. Both the free form and the salts of these end products arewithin the scope of the disclosure. If so desired, one form of acompound may be converted into another form. A free base or acid may beconverted into a salt; a salt may be converted into the free compound oranother salt; a mixture of isomeric compounds of the present disclosuremay be separated into the individual isomers. Compounds of the presentdisclosure, free form and salts thereof, may exist in multipletautomeric forms, in which hydrogen atoms are transposed to other partsof the molecules and the chemical bonds between the atoms of themolecules are consequently rearranged. It should be understood that alltautomeric forms, insofar as they may exist, are included within thedisclosure. Further, a given chemical formula or name shall encompassall conformers, rotamers, or conformational isomers thereof where suchisomers exist. Different conformations can have different energies, canusually interconvert, and are very rarely isolatable. There are somemolecules that can be isolated in several conformations. For example,atropisomers are isomers resulting from hindered rotation about singlebonds where the steric strain barrier to rotation is high enough toallow for the isolation of the conformers. It should be understood thatall conformers, rotamers, or conformational isomer forms, insofar asthey may exist, are included within the present disclosure.

As used herein, the term “substituted” refers to at least one hydrogenatom that is replaced with a non-hydrogen group, provided that normalvalencies are maintained and that the substitution results in a stablecompound. When a substituent is noted as “optionally substituted”, thesubstituents are selected from halo, hydroxyl, alkoxy, oxo, alkanoyl,aryloxy, alkanoyloxy, amino, alkylamino, arylamino, arylalkylamino,disubstituted amines (e.g. in which the two amino substituents areselected from the exemplary group including, but not limited to, alkyl,aryl or arylalkyl), alkanoylamino, aroylamino, aralkanoylamino,substituted alkanoylamino, substituted arylamino, substitutedaralkanoylamino, thiol, alkylthio, arylthio, arylalkylthio, alkylthiono,arylthiono, aryalkylthiono, alkylsulfonyl, aryl sulfonyl,arylalkylsulfonyl, sulfonamide (e.g. —SO₂NH₂), substituted sulfonamide,nitro, cyano, carboxy, unsubstituted amide (i.e. —CONH₂), substitutedamide (e.g. —CONHalkyl, —CONHaryl, —CONHarylalkyl or cases where thereare two substituents on one nitrogen from alkyl, aryl, or alkylalkyl),alkoxycarbonyl, aryl, substituted aryl, guanidine, heterocyclyl (e.g.indolyl, imidazoyl, furyl, thienyl, thiazolyl, pyrrolidyl, pyridyl,pyrimidiyl, pyrrolidinyl, piperidinyl, morpholinyl, piperazinyl,homopiperazinyl and the like), substituted heterocyclyl and mixturesthereof. The substituents may themselves be optionally substituted, andmay be either unprotected, or protected as necessary, as known to thoseof ordinary skill in the art, for example, as taught in Greene, et al.,“Protective Groups in Organic Synthesis”, John Wiley and Sons, SecondEdition, 1991, hereby incorporated by reference in its entirety.

As used herein, the term “alkyl” or “alkylene” unless otherwisespecified refers to both branched and straight-chain saturated aliphaticprimary, secondary, and/or tertiary hydrocarbons having a specifiednumber of carbon atoms. For example, “C₁ to C₆ alkyl” or “C₁₋₆ alkyl”(or alkylene) denotes alkyl chain having 1 to 6 carbon atoms. The alkylor alkylene groups typically include C₁ to C₂₁, for example C₁, C₂, C₃,C₄, C₅, C₆, C₇, C₈, C₉, C₁₀, C₁₁, C₁₂, and specifically includes, but isnot limited to, methyl, trifluoromethyl, ethyl, n-propyl, isopropyl,n-butyl, isobutyl, t-butyl, n-pentyl, isopentyl, neopentyl, n-hexyl,isohexyl, 3-methylpentyl, 2,2-dimethylbutyl, 2,3-dimethylbutyl,2-ethylhexyl, n-heptyl, n-octyl, n-nonyl, 3,7-dimethyloctyl, n-decyl,n-undecyl, n-dodecyl, n-tridecyl, and 2-propylheptyl.

The term “cycloalkyl” refers to cyclized alkyl groups. Exemplarycycloalkyl groups include, but are not limited to, cyclopropyl,cyclobutyl, cyclopentyl, cyclohexyl, norbornyl, and adamantyl. Branchedcycloalkyl groups such as exemplary 1-methylcyclopropyl and2-methylcyclopropyl groups are included in the definition of cycloalkylas used in the present disclosure.

The term “aryl”, as used herein, and unless otherwise specified, refersto a substituent that is derived from an aromatic hydrocarbon (arene)that has had a hydrogen atom removed from a ring carbon atom. Arylincludes phenyl, biphenyl, naphthyl, anthracenyl, and the like.

The term “arylalkyl”, as used herein, refers to a straight or branchedchain alkyl moiety having 1 to 8 carbon atoms that is substituted by anaryl group as defined herein, and includes, but is not limited to,benzyl, phenethyl, 2-methylbenzyl, 3-methylbenzyl, 4-methylbenzyl,2,4-dimethylbenzyl, 2-(4-ethylphenyl)ethyl, 3-(3-propylphenyl)propyl,and the like.

The term “halide”, as used herein, means fluoride, chloride, bromide,and iodide.

The term “halogen”, as used herein, means fluoro, chloro, bromo andiodo.

The present disclosure is intended to include all isotopes of atomsoccurring in the present compounds. Isotopes include those atoms havingthe same atomic number but different mass numbers. By way of generalexample, and without limitation, isotopes of hydrogen include deuteriumand tritium, isotopes of carbon include ¹³C and ¹⁴C, isotopes ofnitrogen include ¹⁴N and ¹⁵N, and isotopes of oxygen include ¹⁶O, ¹⁷Oand ¹⁸O. Isotopically labeled compounds of the disclosure can generallybe prepared by conventional techniques known to those of ordinary skillin the art or by processes and methods analogous to those describedherein, using an appropriate isotopically labeled reagent in place ofthe non-labeled reagent otherwise employed.

For purposes of clarity and in accordance with standard convention inthe art, the symbol

is used in formulas to show the bond that is the point of attachment ofthe moiety or substituent to the core/nucleus of the structure.

As used herein, “formation water” is native water (connate andinterstitial water) present in a subterranean formation.

As used herein, “oil and gas well servicing fluid” (or servicing fluid)means water plus any solids, liquids, and/or gasses entrained thereinthat is injected into a subterranean formation during various drillingoperations. Examples of oil and gas well servicing fluids include, butare not limited to, fracking fluids, drilling fluids, completion fluids,and workover fluids.

“Fracking fluid” (or frac fluid) is an injectable fluid used in frackingoperations to increase the quantity of hydrocarbons that can beextracted. Fracking fluids contain primarily water, and may containproppants (e.g., sand) and other desirable chemicals for modifying wellproduction and fluid properties.

“Drilling fluid” is a circulated fluid system that is used to aid thedrilling of boreholes, for example, to provide hydrostatic pressure toprevent formation fluids from entering into the wellbore, to keep thedrill bit cool and clean during drilling, to carry out drill cuttings,and/or to suspend the drill cuttings while drilling is paused and whenthe drilling assembly is brought in and out of the hole.

“Completion fluid” is a circulated fluid system that is used tocomplete/clean an oil or gas well, i.e., to facilitate final operationsprior to initiation of production, such as setting screens productionliners, packers, downhole valves or shooting perforations into theproducing zone. Completion fluids are typically solids-free brines meantto control a well should downhole hardware fail, without damaging theproducing formation or completion components.

“Workover fluid” is a circulated fluid system that is used duringworkover operations, i.e., to repair or stimulate an existing productionwell for the purpose of restoring, prolonging, and/or enhancing theproduction of hydrocarbons therefrom, and includes stimulation fluidsused in acidizing for example.

As used herein, “wastewater” means a water source obtained from stormdrains, sedimentation ponds, runoff/outflow, landfills, as well as watersources resulting/obtained from industrial processes such as factories,mills, farms, mines, quarries, industrial drilling operations, oil andgas recovery operations, papermaking processes, food preparationprocesses, phase separation processes, washing processes, wastetreatment plants, toilet processes, power stations, incinerators,spraying and painting, or any other manufacturing or commercialenterprise, which comprises water and one or more compounds or materialsderived from such industrial processes, including partially treatedwater from these sources.

As used herein, “produced water”, a particular type of wastewater,refers to water that flows back from a subterranean formation in ahydrocarbon recovery process and comprises one or more natural formationfluids such as formation water, sea water, and hydrocarbon, andoptionally any fluid that has been injected into the subterraneanformation during various drilling operations.

Surfactant

Surfactants are widely used in the oil and gas industry during variousstages of upstream (exploration, field development, and productionoperations) and midstream (transportation e.g., by pipeline, processing,storage, and distribution) oil recovery operations. The surfactants ofthe present disclosure are intended to be useful as a general surfactantin any of these various stages, and may be added to fracking fluids,drilling fluids, completion fluids, workover fluids, among others, foruse for example during drilling, cementing, fracturing, acidizing,demulsification, corrosion inhibition, cleaning, flooding (e.g.,waterflooding, chemical flooding, foam and steam flooding), enhanced oilrecovery, transportation, and the like. In particular, the surfactantsof the present disclosure are suitable for challenging reservoirconditions, such as those where high total dissolved solids (TDS)contents and high temperatures are encountered.

According to a first aspect, the present disclosure thus provides asurfactant of formula (I)

or a solvate, tautomer thereof, or stereoisomer thereof. The differentmoieties present within formula (I) are carefully coordinated in orderto achieve excellent surface properties, solubility in high salinitybrines, and thermal stability. For instance, the amide group [—(O)C—NH—]is thought to advantageously provide low cmc, good biodegradability, andenvironmentally friendliness (lower toxicity). See K. Taleb, M.Mohamed-Benkada, N. Benhamed, S. Saidi-Besbes, Y. Grohens, A. Derdour,Benzene ring containing cationic gemini surfactants: Synthesis, surfaceproperties and antibacterial activity, J. Mol. Liq. 241 (2017) 81-90,incorporated herein by reference in its entirety. Similarly, theunsaturated fatty tail is thought to contribute to low cmc because ofrigidity in the hydrophobic tail. See M.-T. Lee, A. Vishnyakov, A. V.Neimark, Calculations of critical micelle concentration by dissipativeparticle dynamics simulations: the role of chain rigidity, The Journalof Physical Chemistry B 117(35) (2013) 10304-10310, incorporated hereinby reference in its entirety. Moreover, the EO units are thought toimprove solubility of the surfactants in high-salinity brine. See J.Lim, E. Kang, H. Lee, B. Lee, Synthesis and interfacial properties ofethoxylated cationic surfactants derived from n-dodecyl glycidyl ether,Journal of Industrial and Engineering Chemistry 22 (2015) 75-82,incorporated herein by reference in its entirety.

In formula (I), R₁ and R₂ may be the same or different, and each of R₁and R₂ are independently selected from the group consisting of ahydrogen, an optionally substituted alkyl, an optionally substitutedcycloalkyl, and an optionally substituted arylalkyl. For example, eachof R₁ and R₂ may be independently a hydrogen; an optionally substitutedC₁ to C₆ alkyl, preferably an optionally substituted C₂ to C₅ alkyl,preferably an optionally substituted C₃ to C₄ alkyl, preferably anunsubstituted alkyl, for example, methyl, ethyl, or propyl; anoptionally substituted cycloalkyl, preferably an optionally substitutedC₃ to C₆ cycloalkyl, preferably an unsubstituted C₃ to C₆ cycloalkylsuch as cyclopropyl, cyclobutyl, cyclopentyl, and cyclohexyl; anoptionally substituted aryl, preferably an unsubstituted aryl,preferably phenyl; an optionally substituted C₇ to C₁₃ arylalkyl, or anoptionally substituted C₈ to C₁₂ arylalkyl, or an optionally substitutedC₉ to C₁₁ arylalkyl, preferably an unsubstituted arylalkyl with benzylbeing the most preferable. In some embodiments, each of R₁ and R₂ areindependently a hydrogen, or a methyl. In preferred embodiments, each ofR₁ and R₂ are a hydrogen.

R₃ and R₄ may be the same or different and may be independently selectedfrom the group consisting of an optionally substituted alkyl, anoptionally substituted cycloalkyl, and an optionally substitutedarylalkyl. Preferably, R₃ and R₄ may be independently an optionallysubstituted C₁ to C₆ alkyl, an optionally substituted C₂ to C₅ alkyl, oran optionally substituted C₃ to C₄ alkyl. Preferably, each of R₃ and R₄are independently selected from the group consisting of a methyl, anethyl, and an isopropyl. the same. In preferred embodiments, each of R₃and R₄ are a methyl.

The value of x denotes the number of —CH₂— groups connected to theterminal —CH₃ group of the surfactant of formula (I), and may range from2-8, preferably 3-7, preferably 4-6. Most preferably, x is 6.

The value of y denotes the degree of ethoxylation (—O(CH₂)₂—) and y mayrange from 1-15, preferably 2-14, preferably 3-13, preferably 4-12,preferably 5-11, preferably 6-10, preferably 7-9. In a preferredembodiment, each of y is an integer in a range of 2-11, 4-9, or 6-8.Most preferably, y is in a range of 6-11, 7-10, or 8-9.

The value of z may be an integer ranging from 4-10, preferably 5-9,preferably 6-8. In preferred embodiments, z is 6.

The value of n denotes the alkyl chain spacer (—C(R₁)(R₂)—) in betweenthe nitrogen atoms (of the amide and the quaternary amine group), and nmay be an integer in a range of 2-5, preferably 3-4. Most preferably, nis 3.

The ionic headgroup of the surfactant is represented by A in thestructure of formula (I), and in the present disclosure, A is selectedfrom the group consisting of

In some embodiments, A is a carboxybetaine group represented by

In some embodiments, A is a sulfobetaine group represented by

In some embodiments, A is a hydroxy sulfobetaine group represented by

The surfactant herein may be derivable from a mono-unsaturated fattyalcohol (which in turn may be derivable from a mono-unsaturated fattyacid), including both cis- (Z—) unsaturated fatty alcohols such aserucyl alcohol (C22, 13Z), oleyl alcohol (C18, 9Z), palmitoleoyl alcohol(C16, 9Z), myristoleoyl alcohol (C14, 9Z), sapienyl alcohol (C16, 6Z),and the like, as well as trans- (E-) unsaturated fatty alcohols such aselaidyl alcohol (C18, 9E), vaccenyl alcohol (C18, 11E), and the like. Inpreferred embodiments, the surfactant contains a single site ofunsaturation (carbon-carbon double bond), and the single site ofunsaturation is in a cis-(Z—) double bond configuration.

In some embodiments, the surfactant has a critical micelle concentration(CMC) in water at 30 to 60° C. of 3×10⁻⁵ to 5×10⁻⁴M, preferably 3.3×10⁻⁵to 3×10⁻⁴M, preferably 3.5×10⁻⁵ to 1×10⁻⁴ M, preferably 3.6×10⁻⁵ to9×10⁻⁵ M, preferably 5×10⁻⁵ to 7×10⁻⁵ M. In some embodiments, thesurfactant has a surface tension at the critical micelle concentrationof 31-39 mN/m, preferably 32-38 mN/m, preferably 33-37 mN/m, preferably34-36 mN/m, preferably 35 mN/m.

The surfactant of the present disclosure typically has a number averagemolecular weight (Mn) of 415-1,500 g/mol, preferably 450-1,400 g/mol,preferably 500-1,300 g/mol, preferably 600-1,200 g/mol, preferably700-1,150 g/mol, preferably 750-1,100 g/mol, preferably 800-1,050 g/mol,preferably 850-1,000 g/mol, preferably 900-950 g/mol.

In some embodiments, the surfactant of the present disclosure is solublein aqueous fluids, even at high temperatures, such as temperatures of upto 150° C., preferably up to 130° C., preferably up to 100° C.,preferably up to 90° C., preferably up to 80° C., preferably up to 70°C., preferably up to 60° C., preferably up to 50° C., and remainssolubilized at these high temperatures without precipitation or phaseseparation events for prolonged periods such as up to 100 days,preferably up to 90 days, preferably up to 80 days, preferably up to 70days, preferably up to 60 days, preferably up to 50 days. The aqueousfluids may include fresh water (e.g., tap water, distilled water, bidistilled water, deionized water, deionized distilled water, reverseosmosis water, well water, or fresh water obtained from natural sourcessuch as lakes, streams, rivers, etc.) or salt water such as seawater,formation water, produced water, and the like, such as those containingions of sodium, calcium, magnesium, potassium, sulfate, chloride,bicarbonate, carbonate, and/or bromide, and the like.

In preferred embodiments, the surfactant is selected from the groupconsisting of

-   -   wherein in each structure y is 8 or 9.

The surfactant of formula (I) may be prepared, for example, via theroute depicted in FIG. 10 . Briefly, a carboxylic acid of formula (II),or a salt thereof, may be obtained, for example, by ethoxylation andsubsequent carboxymethylation of a suitable mono-unsaturated fattyalcohol including, but not limited to, myristoleoyl alcohol,palmitoleoyl alcohol, sapienyl alcohol, oleyl alcohol, elaidic acid,vaccenic acid, and erucyl alcohol.

where x, y, and z are as defined previously.

The carboxylic acid of formula (II) may next be reacted with a diamineof formula (III) to form a tertiary amido-amine intermediate of formula(IV)

where R₁, R₂, R₃, R₄, x, y, z, and n are all as defined previously.

Exemplary diamines which fall under the general formula (III) and whichmay be used in the amidation reaction include, but are not limited to,3-(dimethylamino)-1-propylamine, 2-(dimethylamino)ethylamine,2-(diethylamino)ethylamine, 1-dimethylamino-2-propylamine,3-(diethylamino)-1-propylamine, (3-amino-2-methylpropyl)dimethylamine,(3-amino-1-methylpropyl)dimethylamine,N,N,2,2-tetramethyl-1,3-propanediamine, 4-(dimethylamino)butylamine,5-(dimethylamino)amylamine, 5-(diethylamino)pentylamine, and5-(diisopropylamino)amylamine.

The amidation may be performed under a wide variety of amide couplingconditions, including using any amidation reagent/catalyst known tothose of ordinary skill in the art to promote/catalyze amide bondformation. In some embodiments, the amidation reaction is performedusing a fluoride salt catalyst, including, but not limited to, sodiumfluoride, potassium fluoride, silver fluoride, cesium fluoride, andtetrabutylammonium fluoride, preferably sodium fluoride. A molar ratioof the fluoride salt to the carboxylic acid of formula (II) may rangefrom 1:5 to 1:20, preferably 1:6 to 1:18, preferably 1:8 to 1:15,preferably 1:9 to 1:12, or about 1:10. Other amide bond formationreagents and catalysts that may be used in addition to or in lieu of thefluoride salt include, but are not limited to, carbodiimides such as1-ethyl-3-(3-dimethylaminopropyl)carbodiimide (EDC),N,N-dicyclohexylcarbodiimide (DCC), 1H-benzotriazole derivatives such as1-[bis(dimethylamino)methylene]-1H-1,2,3-triazolo[4,5-b]pyridinium3-oxid hexafluorophosphate (HATU),O-(benzotriazol-1-yl)-1,1,3,3-tetramethyluronium hexafluorophosphate(HBTU), O-benzotriazol-1-yl-1,1,3,3-tetramethyluronium tetrafluoroborate(TBTU), as well as phosphoric acid, sulfuric acid, boric acid, silicagel, and zeolites, just to name a few, as well as stoichiometriccarboxylic acid activating agents such as oxalyl chloride and thionylchloride. The amidation may be performed using neat (solvent-free) orsolvent-based conditions such as using benzene, xylene,dimethylformamide, tetrahydrofuran, ethyl acetate, diethyl ether,acetonitrile, dimethyl sulfoxide, methylene chloride, chloroform,nitrobenzene, isopropanol, or mixtures thereof. Preferably the amidationis performed under neat conditions. The amidation reaction may beperformed using external heat, for example at a temperature of 50-200°C., preferably 100-190° C., preferably 120-180° C., preferably 130-170°C., preferably 150-160° C. using an external heat source, such as an oilbath, an oven, microwave, or a heating mantle. The mixture may beagitated throughout the duration of the reaction by employing a rotaryshaker, a magnetic stirrer, or an overhead stirrer, or may be left tostand (i.e. not agitated). Drying agents or other water-removingprocedures (e.g., Dean-Stark trap) may optionally be employed tofacilitate the removal of water produced as a by-product. Exemplarydrying agents include, but are not limited to, aluminosilicate minerals,porous glass, activated carbon, clay, zeolites, anhydrous sodiumsulfate, anhydrous magnesium sulfate, anhydrous calcium chloride, andanhydrous calcium sulfate, mesoporous silica, and alumina (Al₂O₃), withmicroporous alumina having an average pore size of 0.2-0.5 nm, or0.3-0.4 nm being the most preferred.

A molar ratio of the diamine of formula (III) to the carboxylic acid offormula (II) may range from 1:1 to 5:1, preferably 2:1 to 4:1,preferably 3:1 to 3.5:1. In some embodiments, the diamine of formula(III) is introduced into the amidation reaction mixture in singleaddition or batch-wise (e.g., two-stage) fashion. For example, whenadded batch-wise, 50-70%, 55-65%, or about 57% of a total molar contentof the diamine may be added as a first portion and allowed to react withthe carboxylic acid for 3-9 hours, 5-7 hours, or about 6 hours, andsubsequently 30-50%, 35-45%, or about 43% of a total molar content ofthe di amine may be added to the same mixture as a second portion andallowed to react with the carboxylic acid for 2-8 hours, 4-6 hours, orabout 5 hours, or until the amid coupling reaction is deemed complete.Alternatively, the diamine may be introduced to the reaction mixture inone batch and allowed to react with the carboxylic acid for 5-20 hours,8-15 hours, or about 12 hours.

The tertiary amido-amine intermediate of formula (IV) may be collectedas an oil, washed in acetone, ethyl acetate, and/or isopropanol and thendried, for example, dried under vacuum until a constant weight isachieved.

The tertiary amido-amine intermediate of formula (IV) is then reactedwith a suitable electrophile forming the surfactant of formula (I),whereby the tertiary amine is converted into a quaternary ammonium saltattached to a desirable anionic headgroup. In some embodiments, theelectrophile is an α-halo acetic acid compound or salt thereof, forexample sodium chloroacetate or sodium bromoacetate, to form thesurfactant of formula (I) where A is a carboxybetaine group representedby

In some embodiments, the electrophile is 1,3-propansultone to form thesurfactant of formula (I) where A is a sulfobetaine group represented by

In some embodiments, the electrophile is a3-halo-2-hydroxypropanesulfonic acid salt (e.g.,3-chloro-2-hydroxypropanesulfonic acid sodium salt) to form thesurfactant of formula (I) where A is a hydroxy sulfobetaine grouprepresented by

A molar ratio of the electrophile to the tertiary amido-amineintermediate of formula (IV) may range from 1:1 to 2:1, preferably 1.1:1to 1.8:1, preferably 1.2:1 to 1.7:1, preferably 1.3:1 to 1.6:1,preferably 1.4:1 to 1.5:1. In some embodiments, the tertiary amido-amineintermediate of formula (IV) is reacted with a suitable electrophile ina polar protic solvent such as water, methanol, ethanol, n-propanol,isopropyl alcohol, n-butanol, and mixtures thereof, preferablyethanol:water mixtures. In some embodiments, the tertiary amido-amineintermediate of formula (IV) is reacted with a suitable electrophile ina polar aprotic solvent including, but not limited to, ethyl acetate,dimethylformamide, tetrahydrofuran, acetone, acetonitrile, and dimethylsulfoxide, preferably ethyl acetate. A base, preferably a carbonate basesuch as sodium carbonate may also optionally be employed during thesurfactant forming step. Reaction between the tertiary amido-amineintermediate of formula (IV) and the electrophile may be thermallypromoted using reaction temperatures of up to 120° C., preferably50-110° C., preferably 60-100° C., preferably 70-95° C., preferably75-90° C., preferably 80-85° C. Typically, the reaction is performed for1-48 hours, preferably 5-24 hours, preferably 10-12 hours.

The surfactant may be isolated and purified from the reaction mixture bymethods known to those of ordinary skill in the art such as filtration,column chromatography, trituration, and high pressure liquidchromatography (HPLC) (normal phase or reversed phase). Preferredmethods include, purifying the reaction mixture with trituration (e.g.,using cold acetone) and/or column chromatography (with silica or aluminaas the stationary phase). In some embodiments, the surfactant ispurified with a silica gel column.

Oil and Gas Well Servicing Fluid

According to a second aspect, the present disclosure relates to an oiland gas well servicing fluid which contains an aqueous base fluid andthe surfactant of the present disclosure. The oil and gas servicingfluid is thus intended to be a general fluid that contains thesurfactant of the present disclosure for use during various stages ofupstream (exploration, field development, and production operations) andmidstream (transportation e.g., by pipeline, processing, storage, anddistribution) oil recovery operations. For example, the oil and gas wellservicing fluid may be used as fracking fluids, drilling fluids,completion fluids, workover fluids, among others, for use for exampleduring drilling, cementing, fracturing, acidizing, demulsification,corrosion inhibition, cleaning, flooding (e.g., waterflooding, chemicalflooding, foam and steam flooding), enhanced oil recovery,transportation, and the like.

In preferred embodiments, the oil and gas well servicing fluid is awater-based fluid. The oil and gas well servicing fluid may beformulated using 40-99.999 wt. %, preferably 50-99.9 wt. %, preferably60-99 wt. %, more preferably 70-95 wt. %, even more preferably 80-90 wt.% of the aqueous base fluid, based on a total weight of the oil and gaswell servicing fluid. The aqueous base fluid may be a fresh water (e.g.,tap water, distilled water, bidistilled water, deionized water,deionized distilled water, reverse osmosis water, well water, or freshwater obtained from natural sources such as lakes, streams, rivers,etc.) or salt water (e.g., seawater, coastal aquifers, formation water,or wastewater having high salinity).

In particular, the surfactant of the present disclosure offers distinctadvantages when employed in harsh oil and gas environments, such as inhigh salinity environments, and thus the servicing fluid may be formedfrom formation water (or diluted formation water) or produced water (ordiluted produced water). The surfactants are thus suitable for use inservicing fluids with a total dissolved solids content of up to 350,000ppm (for example when the servicing fluid is made from formation orproduced water). In some embodiments, the oil and gas well servicingfluid is formed from a salt water as the aqueous base fluid, preferablysea water, formation water, or produced water and may thus have a totaldissolved solids content (TDS) of 50,000-350,000 ppm, preferably55,000-300,000 ppm, preferably 57,000-250,000 ppm, preferably58,000-225,000 ppm, preferably 60,000-220,000 ppm, preferably70,000-215,000 ppm, preferably 80,000-213,000 ppm, preferably90,000-210,000 ppm, preferably 100,000-200,000 ppm, preferably120,000-180,000 ppm, preferably 140,000-160,000 ppm.

Representative examples of cations which may be optionally present inthe oil and gas well servicing fluid include, but are not limited to,sodium, potassium, magnesium, calcium, strontium, barium, iron (ferrousand ferric), lead, copper, cobalt, manganese, nickel, zinc, aluminum,chromium, and titanium, as well as mixtures thereof. Representativeexamples of anions which may be present in the oil and gas wellservicing fluid include, but are not limited to, chloride, carbonate,bicarbonate, sulfate, bromide, iodide, acetate, hydroxide, sulfide,hydrosulfide, chlorate, fluoride, hypochlorite, nitrate, nitrite,perchlorate, peroxide, phosphate, phosphite, sulfite, hydrogenphosphate, hydrogen sulfate, as well as mixtures thereof.

While the amounts of individual ions present may vary significantlybased on the location of the well, the water source used to formulatethe servicing fluid, whether or not the water source is diluted, etc.,the oil and gas well servicing fluid may generally contain up to 320,000ppm total of monovalent ions, for example at least 300 ppm, preferablyat least 400 ppm, preferably at least 500 ppm, preferably at least 1,000ppm, preferably at least 2,000 ppm, preferably at least 5,000 ppm,preferably at least 10,000 ppm, preferably at least 15,000 ppm,preferably at least 20,000 ppm, preferably at least 50,000 ppm,preferably at least 100,000 ppm, preferably at least 125,000 ppm,preferably at least 150,000 ppm, preferably at least 175,000 ppm,preferably at least 190,000, and up to 320,000 ppm, preferably up to300,000 ppm, preferably up to 275,000 ppm, preferably up to 250,000 ppm,preferably up to 225,000 ppm, preferably up to 200,000 ppm total ofmonovalent ions. In some embodiments, chloride ions may be present inthe oil and gas well servicing fluid in amounts of at least 100 ppm,preferably at least 1,000 ppm, preferably at least 5,000 ppm, preferablyat least 10,000 ppm, preferably at least 20,000 ppm, preferably at least25,000 ppm, and up to 250,000 ppm, preferably up to 200,000 ppm,preferably up to 175,000 ppm, preferably up to 150,000 ppm, preferablyup to 135,000 ppm, preferably up to 100,000 ppm, preferably up to 50,000ppm, preferably up to 35,000 ppm. In some embodiments, sodium ions maybe present in the oil and gas well servicing fluid in amounts of atleast 50 ppm, preferably at least 100 ppm, preferably at least 1,000ppm, preferably at least 5,000 ppm, preferably at least 10,000 ppm,preferably at least 15,000 ppm, and up to 60,000 ppm, preferably up to55,000 ppm, preferably up to 45,000 ppm, preferably up to 30,000 ppm,preferably up to 25,000 ppm, preferably up to 20,000 ppm.

The amount of the surfactant of formula (I) present in the oil and gaswell servicing fluid may be varied depending on the drilling operation,wellbore conditions, and the nature of other components in the oil andgas well servicing fluid. However, typically, the surfactant disclosedherein is employed in an amount of 0.001-15 wt. %, preferably 0.005-14wt. %, preferably 0.01-13 wt. %, preferably 0.015-12 wt. %, preferably0.02-11 wt. %, preferably 0.025-10 wt. %, preferably 0.03-8 wt. %,preferably 0.035-6 wt. %, preferably 0.04-4 wt. %, preferably 0.045-2wt. %, preferably 0.05-1 wt. %, preferably 0.055-0.5 wt. %, preferably0.06-0.1 wt. % relative to a total weight of the oil and gas wellservicing fluid.

The oil and gas well servicing fluid may optionally contain an oil/oilphase, for example, the oil and gas well servicing fluid may contain upto 20 wt. % of an oil phase, preferably 0.05-15 wt. %, preferably 0.5-10wt. %, preferably 1-9 wt. %, preferably 1.5-8 wt. %, preferably 2-7 wt.%, preferably 2.5-6 wt. %, preferably 3-5 wt. %, preferably 3.5-4 wt. %,of an oil/oil phase, based on a total weight of the oil and gas wellservicing fluid. In some embodiments, the oil is obtained from asubterranean reservoir and the oil is crude oil. The crude oil may be avery light crude oil such as Arab Extra Light, Arab Super Light, or ArabSuper Light Ardjuna crude oil (e.g., a jet fuel, gasoline, kerosene,petroleum ether, petroleum spirit, or petroleum naphtha crude oil), alight crude oil such as Arab Light or Arab Light/Seg 17 Blend crude oil(e.g., grade 1 and grade 2 fuel oil, diesel fuel oil, domestic fueloil), a medium crude oil such as Arab Medium crude oil, and a heavycrude oil such as Arab Heavy crude oil (e.g., grade 3, 4, 5, and 6 fueloil, heavy marine fuel), including both sweet (sulfur volume lower than0.50%) and sour (sulfur volume higher than 0.50%) crude oils varieties.Of course, the oil/oil phase is not limited to crude petroleum oil, butextends to any hydrocarbon which may be added during oil recoveryoperations, such as kerosene, gasoline, diesel oils, gas oils, fueloils, paraffin oils, mineral oils (e.g., refined mineral oil, lowtoxicity mineral oils), other petroleum distillates, synthetic oils(e.g., polyolefins, polydiorganosiloxanes, siloxanes, organosiloxanes),as well as mixtures thereof.

In some embodiments, the oil and gas well servicing fluid has a pH of atleast 1, preferably at least 2, preferably at least 3, preferably atleast 4, preferably at least 5, preferably at least 6, preferably atleast 7, and up to 14, preferably up to 13, preferably up to 12,preferably up to 11, preferably up to 10, preferably up to 9, preferablyup to 8.

In addition to being compatible with the various salts and ionic speciesprovided above, even in water sources having an extremely high TDScontent, the surfactant of the present disclosure is also compatiblewith a wide range of components, species, chemistries, materials,additives common to oil and/or gas production. For example, the oil andgas well servicing fluid may be used as a fracking fluid, a drillingfluid, a completion fluid, and/or a workover fluid, and may additionallycomprise one or more of oil (e.g., produced petroleum), natural gas,carbon dioxide, hydrogen sulfide, organosulfur (e.g., a mercaptan),hydronium ions, oxygen, etc., as well as one or more of otherchemistries/materials/additives known to those of ordinary skill in theart used to effect production or fluid properties during oil recoveryoperations. Such other chemistries/materials/additives may be usedduring various oil and gas well operations in art acceptable quantities.For example, secondary surfactants may be optionally included in the oiland gas well servicing fluids herein, including cationic, anionic,non-ionic, and/or amphoteric secondary surfactants.

Cationic surfactants may include, but are not limited to

-   -   a protonated amine formed from a reaction between a C₆-C₂₆ alkyl        amine compound and an acid (e.g., acetic acid, formic acid,        propionic acid, butyric acid, pentanoic acid, hexanoic acid,        oxalic acid, malonic acid, lactic acid, glyceric acid, glycolic        acid, malic acid, citric acid, benzoic acid, p-toluenesulfonic        acid, trifluoromethanesulfonic acid, hydrochloric acid, nitric        acid, phosphoric acid, sulfuric acid, hydrobromic acid,        perchloric acid, hydroiodic acid, etc.), such as protonated        salts of C₆-C₂₆ alkyl monoamines, C₆-C₂₆ alkyl (poly)alkylene        polyamines, and alkoxylated fatty amines;    -   a protonated C₆-C₂₆ alkyl amidoamine formed from a reaction        between a C₆-C₂₆ alkyl amidoamine compound and an acid (for        example the acids listed above), such as protonated forms of the        amide reaction product between any fatty acid previously listed        (or ester derivative thereof) with a polyamine (e.g.,        putrescine, cadaverine, ethylene diamine,        N¹,N¹-dimethylethane-1,2-diamine,        N¹,N¹-dimethylpropane-1,3-diamine,        N¹,N¹-diethylethane-1,2-diamine,        N¹,N¹-diethylpropane-1,3-diamine, spermidine,        1,1,1-tris(aminomethyl)ethane, tris(2-aminoethyl)amine,        spermine, TEPA, DETA, TETA, AEEA, PEHA, HEHA, dipropylene        triamine, tripropylene tetramine, tetrapropylene pentamine,        pentapropylene hexamine, hexapropylene heptamine, dibutylene        triamine, tributylene tetramine, tetrabutylene pentamine,        pentabutylene hexamine, hexabutylene heptamine), with specific        mention being made to protonated forms of        stearamidopropyldimethylamine, stearamidopropyldiethylamine,        stearamidoethyldiethylamine, stearamidoethyldimethylamine,        palmitamidopropyldimethylamine, palmitamidopropyldiethylamine,        palmitamidoethyldiethylamine, palmitamidoethyldimethylamine,        behenamidopropyldimethylamine, behenamidopropyldiethylmine,        behenamidoethyldiethylamine, behenamidoethyldimethylamine,        arachidamidopropyldimethylamine, arachidamidopropyldiethylamine,        arachidamidoethyldiethylamine, and        arachidamidoethyldimethylamine; and    -   a quaternary ammonium compound made from alkylation with        suitable alkylating agents (e.g., dimethyl sulfate, methyl        chloride or bromide, benzyl chloride or bromide, C₆-C₂₆ alkyl        chloride or bromide, etc.) of a tertiary C₆-C₂₆ alkyl amine, an        alkoxylated (tertiary) amine, or an aprotic nitrogenous        heteroarene (optionally substituted) having at least one        aromatic nitrogen atom with a reactive lone pair of electrons,        with specific mention being made to a tri-fatty alkyl lower        alkyl ammonium compound (e.g., trioctyl methyl ammonium        chloride), a C₁₀-C₁₈ alkyl trimethyl ammonium chloride or        methosulfate, a di-C₁₀-C₁₈ alkyl dimethyl ammonium chloride or        methesulfate, a C₁₀-C₁₈ alkyl benzyl dimethyl ammonium chloride,        a methyl quaternized C₆-C₂₂ alkyl propylene diamine, a methyl        quaternized C₆-C₂₂ alkyl propylene triamine, a methyl        quaternized C₆-C₂₂ alkyl propylene tetraamine, a N—C₁₀-C₁₈alkyl        pyridinium or a quinolinium bromide or chloride such as N-octyl        pyridinium bromide, N-nonyl pyridinium bromide, N-decyl        pyridinium bromide, N-dodecyl pyridinium bromide, N-tetradecyl        pyridinium bromide, N-dodecyl pyridinium chloride, N-cyclohexyl        pyridinium bromide, naphthyl methyl quinolinium chloride,        naphthyl methyl pyridinium chloride, and cetylpyridinium        chloride (for example those disclosed in        CN101544903B—incorporated herein by reference in its entirety);    -   as well as mixtures thereof.

Anionic surfactants may include, but are not limited to:

-   -   sulfates, such as alkyl sulfates, alkyl-ester-sulfates, alkyl        ether sulfates, alkyl-alkoxy-ester-sulfate, sulfated        alkanolamides, glyceride sulfates, in particular, sulfates of        fatty alcohols or polyoxyalkylene ethers of fatty alcohols such        as sodium dodecyl sulfate, sodium laureth sulfate, ammonium        lauryl sulfate, potassium lauryl sulfate, sodium myreth sulfate;    -   sulfonates such as alkyl sulfonates, fatty alkyl-benzene        sulfonates, lower alkyl-benzene sulfonates, alpha olefin        sulfonates, lignosulfonates, sulfo-carboxylic compounds, for        example, dodecyl benzene sulfonate, dioctyl sodium        sulfosuccinate, perfluorooctanesulfonate (PFOS),        perfluorobutanesulfonate;    -   phosphates such as alkyl aryl ether phosphates, alkyl ether        phosphates, phosphates of fatty alcohols or polyoxyalkylene        ethers of fatty alcohols such as cetyl phosphate salts, dicetyl        phosphate salts, ceteth-10-phosphate salts;    -   carboxylate salts of fatty acids, acylamino acids, lactylates,        and/or fatty alcohols/polyoxyalkylene ethers of fatty alcohols        such as sodium stearate, vegetable oil-based anionic surfactants        (e.g., palm oil anionic surfactant), sodium behenoyl lactylate,        sodium isostearoyl lactylate, sodium caproyl lactylate, sodium        laureth-5 carboxylate, sodium laureth-6 carboxylate, sodium        laureth-11 carboxylate,    -   and mixtures thereof.

Non-ionic surfactants may include, but are not limited to:

-   -   amides or alkanolamides of fatty acids, that is, amide reaction        products between a fatty acid and an amine or alkanolamine        compound, such as coconut fatty acid monoethanolamide (e.g.,        N-methyl coco fatty ethanol amide), coconut fatty acid        diethanolamide, oleic acid diethanolamide, palm based        oleylamine, and vegetable oil fatty acid diethanolamide;    -   alkoxylated alkanolamides of fatty acids, preferably ethoxylated        and/or propoxylated variants of the alkanolamides of fatty acids        using for example anywhere from 2 to 30 EO and/or PO molar        equivalents, preferably 3 to 15 EU and/or PU molar equivalents,        preferably 4 to 10 EU and/or PU molar equivalents, preferably 5        to 8 EU and/or PU molar equivalents per moles of the        alkanolamide of the fatty acid (e.g., coconut fatty acid        monoethanolamide with 4 moles of ethylene oxide);    -   amine oxides, such as N-cocoamidopropyl dimethyl amine oxide and        dimethyl C₆-C₂₂ alkyl amine oxide (e.g., dimethyl coco amine        oxide);    -   fatty esters, such as ethoxylated and/or propoxylated fatty        acids (e.g., castor oil with 2 to 40 moles of ethylene oxide),        alkoxylated glycerides (e.g., PEG-24 glyceryl monostearate),        glycol esters and derivatives, monoglycerides, polyglyceryl        esters, esters of polyalcohols, and sorbitan/sorbitol esters;    -   ethers, such as (i) alkoxylated C₁-C₂₂ alkanols, which may        include alkoxylated C₁-C₅ alkanols, preferably ethoxylated or        propoxylated C₁-C₅ alkanols (e.g., dipropylene glycol n-butyl        ether, tripropylene glycol n-butyl ether, dipropylene glycol        methyl ether, tripropylene glycol methyl ether, diethylene        glycol n-butyl ether, triethylene glycol n-butyl ether,        diethylene glycol methyl ether, triethylene glycol methyl ether)        and alkoxylated C₆-C₂₆ alkanols (including alkoxylated fatty        alcohols), preferably alkoxylated C₇-C₂₂ alkanols, more        preferably alkoxylated C₈-C₁₄ alkanols, preferably ethoxylated        or propoxylated (e.g., cetyl stearyl alcohol with 2 to 40 moles        of ethylene oxide, lauric alcohol with 2 to 40 moles of ethylene        oxide, oleic alcohol with 2 to 40 moles of ethylene oxide,        ethoxylated lanoline derivatives, laureth-3, ceteareth-6,        ceteareth-11, ceteareth-15, ceteareth-16, ceteareth-17,        ceteareth-18, ceteareth-20, ceteareth-23, ceteareth-25,        ceteareth-27, ceteareth-28, ceteareth-30, isoceteth-20,        laureth-9/myreth-9, and PPG-3 caprylyl ether); (ii) alkoxylated        polysiloxanes; (iii) ethylene oxide/propylene oxide copolymers        (e.g., PPG-1-PEG-9-lauryl glycol ether, PPG-12-buteth-16,        PPG-3-buteth-5, PPG-5-buteth-7, PPG-7-buteth-10,        PPG-9-buteth-12, PPG-12-buteth-16, PPG-15-buteth-20,        PPG-20-buteth-30, PPG-28-buteth-35, and PPG-33-buteth-45);        and (iv) alkoxylated alkylphenol s;    -   alkyl polyglycosides (APGs) such as those made from reaction        between fatty alcohols and glucose;    -   and mixtures thereof.

Amphoteric surfactants may include, but are not limited to:

-   -   C₆-C₂₂ alkyl dialkyl betaines, such as fatty dimethyl betaines        (R—N(CH₃)₂(⁺)—CH₂COO⁻), obtained from a C₆-C₂₂ alkyl dimethyl        amine which is reacted with a monohaloacetate salt (e.g., sodium        monochloroacetate), such as C₁₂-C₁₄ dimethyl betaine        (carboxylate methyl C₁₂-C₁₄ alkyl dimethylammonium);    -   C₆-C₂₂ alkyl amido betaines        (R—CO—NH—CH₂CH₂CH₂—N(CH₃)₂(⁺)—CH₂COO⁻ or        R—CO—NH—CH₂CH₂—N(CH₃)₂(⁺)—CH₂COO⁻), obtained by the reaction of        a monohaloacetate salt (e.g., sodium monochloroacetate) with the        reaction product of either dimethyl amino propylamine or        dimethyl amino ethylamine with a suitable carboxylic acid or        ester derivatives thereof, such as C₁₀-C₁₈ amidopropyl        dimethylamino betaine;    -   C₆-C₂₂ alkyl sultaines or C₆-C₂₂ alkyl amido sultaines, which        are similar to those C₆-C₂₂ alkyl dialkyl betaines or C₆-C₂₂        alkyl amido betaines described above except in which the        carboxylic group has been substituted by a sulfonic group        (R—N(CH₃)₂O—CH₂CH₂CH₂SO₃ ⁻ or        R—CO—NH—CH₂CH₂CH₂—N(CH₃)₂(⁺)CH₂CH₂CH₂SO₃ ⁻ or        R—CO—NH—CH₂CH₂—N(CH₃)₂(⁺)—CH₂CH₂CH₂SO₃ ⁻) or a hydroxysulfonic        group (R—N(CH₃)₂(⁺)—CH₂CH(OH)—CH₂SO₃ ⁻ or        R—CO—NH—CH₂CH₂CH₂—N(CH₃)₂(⁺)—CH₂CH(OH)—CH₂SO₃ ⁻ or        R—CO—NH—CH₂CH₂—N(CH₃)₂(⁺)—CH₂CH(OH)—CH₂SO₃ ⁻), such as C₁₀-C₁₈        dimethyl hydroxysultaine and C₁₀-C₁₈ amido propyl dimethylamino        hydroxysultaine;    -   and mixtures thereof.

In some embodiments, the only surfactant present in the oil and gas wellservicing fluids herein are surfactants represented by formula (I).

Other chemistries/materials/additives which may be optionally includedin the oil and gas well servicing fluid in art appropriate levels,include, but are not limited to,

-   -   pH regulating agents e.g., H₂SO₄, HCl, NaOH, phosphate buffers        such as monosodium phosphate, disodium phosphate, sodium        tripolyphosphate buffers, borate buffers;    -   viscosity modifying agents e.g., bauxite, bentonite, dolomite,        limestone, calcite, vaterite, aragonite, magnesite, taconite,        gypsum, quartz, marble, hematite, limonite, magnetite, andesite,        garnet, basalt, dacite, nesosilicates or orthosilicates,        sorosilicates, cyclosilicates, inosilicates, phyllosilicates,        tectosilicates, kaolins, montmorillonite, fullers earth, and        halloysite xanthan gum, psyllium husk powder, hydroxyethyl        cellulose, carboxymethylcellulose, and polyanionic cellulose,        poly(diallyl amine), diallyl ketone, diallyl amine, styryl        sulfonate, vinyl lactam, laponite;    -   chelating agents e.g., ethylene diamine tetraacetic acid (EDTA),        diethylene triamine pentaacetic acid (DPTA), hydroxyethylene        diamine triacetic acid (HEDTA), ethylene diamine        di-ortho-hydroxy-phenyl acetic acid (EDDHA), ethylene diamine        di-ortho-hydroxy-para-methyl phenyl acetic acid (EDDHMA),        ethylene diamine di-ortho-hydroxy-para-carboxy-phenyl acetic        acid (EDDCHA);    -   stabilizing agents e.g., ethylene glycol, propylene glycol,        glycerol, polypropylene glycol, polyethylene glycol,        carboxymethyl cellulose, hydroxyethyl cellulose, xanthan gums,        polyacrylamides, polysiloxane polyalkyl polyether copolymers,        acrylic copolymers, alkali metal alginates and other water        soluble alginates, carboxyvinyl polymers, polyvinylpyrollidones,        polyacrylates;    -   intensifiers e.g., formic acid, C₁-C₄ alkyl formates such as        methyl formate and ethyl formate, benzyl formate, formamide,        dimethyl formamide, 1,1′-azobisformamide, metal halides such as        sodium bromide, potassium bromide, sodium iodide, potassium        iodide, copper(I) chloride, copper(I) iodide, copper(II)        chloride, copper(II) iodide, antimony chloride, preferably CuI,        KI, and formic acid, more preferably CuI;    -   corrosion inhibitors e.g., polyureas, alkoxylated fatty amines,        chromates, zinc salts, (poly)phosphates, organic phosphorus        compounds (phosphonates), acetylenic alcohols such as        propargylic alcohol, α,β-unsaturated aldehydes such as        cinnameldehyde and crotonaldehyde, aromatic aldehydes such as        furfural, p-anisaldehyde, phenones including alkenyl phenones        such as phenyl vinyl ketone, nitrogen-containing heterocycles        such as imidazolines, piperazines, hexamethylene tetramines,        quaternized heteroarenes such as 1-(benzyl)quinolinium chloride,        and condensation products of carbonyls and amines such as Schiff        bases;    -   dispersing agents e.g., polymeric or co-polymeric compounds of        polyacrylic acid, polyacrylic acid/maleic acid copolymers,        styrene/maleic anhydride copolymers, polymethacrylic acid and        polyaspartic acid;    -   scale inhibitors e.g., sodium hexametaphosphate, sodium        tripolyphosphate, hydroxyethylidene diphosphonic acid,        aminotris(methylenephosphonic acid (ATMP), vinyl sulfonic acid,        allyl sulfonic acid, polycarboxylic acid polymers such as        polymers containing 3-allyloxy-2-hydroxy-propionic acid        monomers, sulfonated polymers such as vinyl monomers having a        sulfonic acid group, polyacrylates;    -   defoaming agents e.g., silicone oils, silicone oil emulsions,        organic defoamers, emulsions of organic defoamers,        silicone-organic emulsions, silicone-glycol compounds,        silicone/silica adducts, emulsions of silicone/silica adducts;    -   proppants e.g., sand, ceramic, silica, quartz, or other        particulates that prevent fractures from closing when injection        is stopped;    -   emulsifiers such as a tallow amine, a ditallow amine, or        combinations thereof, for example a 50% concentration of a        mixture of tallow alkyl amine acetates, C16-C18 (CAS 61790-60)        and ditallow alkyl amine acetates (CAS 71011-03-5) in a suitable        solvent such as heavy aromatic naphtha and ethylene glycol;    -   clay swelling inhibitors e.g., potassium chloride, potassium        bromide, potassium formate, potassium fluoride, and potassium        iodide;    -   winterizers e.g., methanol;    -   as well as other oil/gas production additives such as hydrate        inhibitors, asphaltene inhibitors, paraffin inhibitors, H₂S        scavengers, O₂ scavengers, CO₂ scavengers, friction reducing        agents, water clarifiers, breakers, biocides, crosslinkers,        among many others;    -   as well as mixtures thereof.        Methods of Servicing an Oil and Gas Well

A third aspect of the present disclosure relates to a method ofservicing an oil and gas well during fracking, drilling, completion,and/or workover using the oil and gas well servicing fluid. The methodherein is not limited to any particular type of well, as vertical,horizontal, multilateral, and extended reach wells may be serviced withthe disclosed oil and gas well servicing fluid. The surfactant iscompatible with, and thus may be added to, any subterranean geologicalformation including a shale formation, a clay formation, a carbonateformation, a sandstone formation, or the like. In some embodiments, thesubterranean geological formation is a shale formation, which containsclay minerals and quartz. In some embodiments, the subterraneangeological formation is a clay formation, which contains chlorite,illite, kaolinite, montmorillonite and smectite. In some embodiments,the subterranean geological formation is a carbonate formation, e.g.limestone or dolostone, which contains carbonate minerals, such ascalcite, aragonite, dolomite, etc., or a sandstone formation, forexample, a formation which contains quartz, feldspar, rock fragments,mica and numerous additional mineral grains held together with silicaand/or cement.

A pumping system may be used to circulate the oil and gas well servicingfluid in a wellbore during the desired servicing operation. Use of theoil and gas well servicing fluid for a particular operation also doesnot preclude the use of other servicing operations. For example, the oiland gas well servicing fluid may be used as a drilling fluid and otheroperations may still be used in conjunction with or sequential to, thedrilling operation, such as pre-flush treatments, after-flushtreatments, hydraulic fracturing treatments, sand control treatments(e.g., gravel packing), “frac pack” treatments, matrix acidizing,wellbore clean-out treatments, cementing operations, workovertreatments, etc.

The servicing fluid may be directly injected into a pipe in fluidcommunication with the subterranean reservoir, optionally underpressure, or alternatively the surfactant of formula (I) may be directlyinjected into the subterranean reservoir where it is combined with anaqueous base fluid (e.g., formation water) thereby forming the servicingfluid. In any of the above applications, the surfactant/servicing fluidmay be injected continuously and/or in batches. In some embodiments, theoil and gas servicing fluid is used for fracking operations and isinjected into the well at pressures above the fracture point of theformation, for example pressures of up to 15,000 psi, preferably up to13,000 psi, preferably up to 10,000 psi, preferably up to 9,000 psi,preferably up to 8,000 psi, preferably up to 7,000 psi, preferably up to6,000 psi, preferably up to 5,000 psi. In some embodiments, the oil andgas well servicing fluid is injected at pressures less than the fracturepressure of the formation, for example at pressures of up to 4,000 psi,preferably up to 3,000 psi, preferably up to 2,000 psi, preferably up to1,000 psi, preferably up to 800 psi, preferably up to 600 psi,preferably up to 400 psi, preferably up to 200 psi, preferably up to 100psi, preferably up to 80 psi, preferably up to 60 psi, preferably up to40 psi, preferably up to 35 psi, preferably up to 30 psi, preferably upto 25 psi, preferably up to 20 psi.

The servicing fluid may be injected using addition/dosing/mixingtechniques known by those of ordinary skill in the art, including bothmanual and automatic addition techniques. For example, the addition maybe carried out by using inline static mixers, inline mixers withvelocity gradient control, inline mechanical mixers with variable speedimpellers, inline jet mixers, motorized mixers, batch equipment, andappropriate chemical injection pumps and/or metering systems. Thechemical injection pump(s) can be automatically or manually controlledto inject any amount of the surfactant/servicing fluid.

The surfactants described herein are effective under a variety ofconditions, even under harsh conditions which may be encountered duringchallenging oil/gas recovery operations (high temperature and/or highsalinity environments). In some embodiments, the surfactants preventprecipitation and/or phase separation events at temperatures of 30-150°C., preferably 40-140° C., preferably 50-130° C., preferably 60-120° C.,preferably 70-110° C., preferably 80-100° C., preferably 90-95° C. Inparticular, the surfactants remain effective at these high temperatureseven in high salinity environments, such as those with the totaldissolved solids contents described previously, for prolonged periods oftime, e.g., up to 100 days, preferably up to 90 days, preferably up to80 days, preferably up to 70 days, preferably up to 60 days, preferablyup to 50 days.

The examples below are intended to further illustrate protocols forpreparing/characterizing the surfactants of formula (I), and usesthereof, and are not intended to limit the scope of the claims.

EXAMPLES

Experimental

Material

Glycolic acid ethoxylate oleyl ether, 3-(dimethylamino)-1-propylamine(99%), 1,3-propanesultone (98%), 3-chloro-2-hydroxypropanesulfonic acidsodium salt (95%), sodium chloroacetate (98%), sodium fluoride (≥99%),Aluminum oxide (≥98% Al₂O₃ basis) were purchased from Aldrich companySolvents were purified through distillation for the preparation of OPAC,OPAS, and OPAH. Salts were purchased from Aldrich company for thepreparation of seawater (SW) and formation water (FW), including sodiumbicarbonate (NaHCO₃), sodium chloride (NaCl), calcium chloride (CaCl₂),sodium sulfate (Na₂SO₄), and magnesium sulfate (MgSO₄) The amount ofeach salt in SW and FW is depicted in Table 1.

TABLE 1 The composition of seawater and formation water FW SW Ions (gL⁻¹) (g L⁻¹) Na⁺ 59.5 18.3 Ca²⁺ 19.1 0.7 Mg²⁺ 2.5 2.1 So₄ ²⁻ 0.4 4.3 Cl⁻132.1 32.2 HCO₃ ⁻ 0.4 0.1 Total 214 57.7Structure Elucidation

NMR (Nuclear Magnetic Resonance) study was done with the help of JEOL1500 machine (500 MHz). TMS was used as an internal standard, sampleswere dissolved in chloroform-d, and readings were recorded in ppm. FTIRanalysis was conducted with the help of Perkin-Elmer instrument (16Fmodel) and readings were noted in cm⁻¹.

Thermogravimetric Analysis (TGA)

TGA graph was obtained using SDT Q600 machine (TA instrument) withcontinuous heating at 20° C./min. The heating range 30-500° C. with astable flow of nitrogen at 100 mL/min.

Salt Tolerance

10 wt % solutions of OPAC, OPAS, and OPAH were prepared in DW, SW, andFW and kept in the oven for 90 days at 90° C. A transparent solutionafter 90 days revealed that OPAC, OPAS, and OPAH are compatible andsoluble with all kinds of water. Less soluble material exhibit phaseseparation and/or precipitation when dissolved in water.

Surface Tension

Surface activities of OPAC, OPAS, and OPAH were determined using a forcetensiometer with a platinum Wilhelmy plate (Sigma 702, BiolinScientific). The test temperatures were 30° C. and 60° C. The plate wasflushed with deionized water before heating it red hot to ensure it wasproperly cleaned. The surface tension of deionized water was measuredthree times to check if the cleanup procedure yielded repeatableresults. The samples were covered to minimize evaporation, but withenough space to let the plate go through the covering during themeasurement.

The surface tension data was used to estimate other properties using thefollowing equations:

$\begin{matrix}{\pi_{cmc} = {\gamma_{0} - \gamma_{cmc}}} & (1)\end{matrix}$ $\begin{matrix}{\Gamma_{\max} = {{- \frac{1}{nRT}}\left( \frac{d\gamma}{dInC} \right)_{\tau}}} & (2)\end{matrix}$ $\begin{matrix}{A_{\min} = {10^{18}/N_{A}\Gamma_{\max}}} & (3)\end{matrix}$where cmc is critical micelle concentration, γ₀ represents surfacetension of water without surfactant, γ_(cmc) is surface tension at cmc,π_(cmc) Represents the ability of the surfactant to reduce the surfacetension, r_(max) is the maximum surface access, Avogadro number isrepresented by N_(A), dγ/dlnC is the slope, C represents theconcentration of surfactant, temperature, and gas constant arerepresented by T and R, respectively, A_(min) is the minimum area permolecule, and the values of n is 1 for zwitterionic surfactants.Synthesis

Synthesis of Tertiary Amido-Amine Intermediate (4)

The intermediate compound (4) was synthesized by following the methodoutlined in FIG. 10 . See Z. Chu, Y. Feng, A facile route towards thepreparation of ultra-long-chain amidosulfobetaine surfactants, Synlett2009(16) (2009) 2655-2658, incorporated herein by reference in itsentirety. 3-(dimethylamino)-1-propylamine (5) (2.92 g, 85.71 mmol),glycolic acid ethoxylate oleyl ether (6) (30 g, 42.86 mmol), NaF (0.18g, 4.29 mmol) were refluxed in 200 mL 3-necked RB flask for 6 hours at160° C. The resulting water as a byproduct was collected with the helpof Al₂O₃. The reaction continued for 6 h and then additional3-(dimethylamino)-1-propylamine (6.57 g, 64.29 mmol) was injected in thereaction flask and reaction continued for further 5 hours. Aftercompletion of the reaction, the residual 3-(dimethylamino)-1-propylaminewas separated, and the crude product was dissolved in acetone, filtered,and vacuumed to attain tertiary amido-amine (4), which is a yellowishviscous material. ¹H-NMR (500 MHz, CDCl₃, TMS) δ ppm: 0.87 (t, J=6.7 Hz,CH₃), 1.14-1.34 (m, (CH₂)_(n)), 1.51-1.61 (m, CH₂), 1.70 (t, J=7.0 Hz,CH₂), 2.03 (m, (CH₂)₂), 2.24 (s, (2×CH₃), 2.36 (t, J=7.0 Hz, CH₂),3.30-3.40 (m, CH₂), 3.45 (t, J=7.0 Hz, CH₂), 3.55-3.60 (m, CH₂),3.61-3.71 (m, (OCH₂CH₂)_(n)), 4.00 (s, CH₂), 5.34 (m, CH═CH), 7.54 (s,NH).

Synthesis of Oleyl Polyoxyethylene Amindopropyl Carboxybetaine (OPAC)

The intermediate 4 (10.0 g, 12.76 mmol) and sodium chloroacetate (3)(1.86 g, 15.94 mmol) were dissolved in ethanol:water (75:15 mL) usinground bottom flask (3-necked, 500 Ml). The experiment was continued at85° C. for 12 hours. The pale yellow viscous material was obtained,filtered, washed with ethyl acetate (3×50 mL). The viscous product wasfurther purified using column chromatography. The column was filled withsilica and ethanol was used as a mobile phase to achieve the requiredsurfactant OPAC (See Y. Zhang, Y. Luo, Y. Wang, J. Zhang, Y. Feng,Single-component wormlike micellar system formed by a carboxylbetainesurfactant with C22 saturated tail, Colloids and Surfaces A:Physicochemical and Engineering Aspects 436 (2013) 71-79, incorporatedherein by reference in its entirety), which was obtained as a colorlessgel. ¹H-NMR (500 MHz, CDCl₃, TMS) δ ppm: 0.88 (t, CH₃, J=6.7 Hz),1.16-1.36 (m, (CH₂)_(n)), 1.53-1.63 (m, CH₂), 1.95-2.05 (m, (CH₂)₂),3.24 (s, 2×CH₃), 3.31-3.41 (m, CH₂), 3.41-3.51 (m, CH₂), 3.52-3.72 (m,(OCH₂CH₂)—), 4.00 (m, CH₂), 5.34 (m, CH═CH), 8.00 (s, NH). ¹³C-NMR δ(ppm): 14.1, 22.7, 24.8, 26.1, 27.2, 29.2, 29.3, 29.4, 29.5, 29.6, 29.7,29.8, 31.9, 35.9, 42.8, 51.5, 55.3, 61.6, 64.4, 69.1-72.7, 129.8, 129.9,165.0, 170.8. FT-IR υ (cm⁻¹) 3398, 2923, 2855, 1634, 1460, 1394, 1348,1250, 1095, 946.

Synthesis of Oleyl Polyoxyethylene Amidopropyl Sulfobetaine (OPAS)

The intermediate 4 (10.0 g, 12.76 mmol) and 1,3-propanesultone (2) (2.34g, 19.13 mmol) were dissolved in ethyl acetate (100 mL) using a roundbottom flask (3-necked, 500 mL). The experiment was continued at 80° C.for 12 hours. The pale yellow viscous gel was received, dissolved incold acetone (3×50 mL), filtered, and vacuumed to obtain OPAS (See Z.Chu, Y. Feng, A facile route towards the preparation of ultra-long-chainamidosulfobetaine surfactants, Synlett 2009 (16) (2009) 2655-2658,incorporated herein by reference in its entirety) as a colorless viscousmaterial. ¹H-NMR (500 MHz CDCl₃, TMS) δ ppm: 0.88 (t, CH₃, J=6.7 Hz),1.17-1.37 (m, (CH₂)_(n)), 1.53-1.63 (m, CH₂), 1.95-2.05 (m, (CH₂)₃),2.16-2.26 (m, CH₂), 2.85-2.95 (m, (CH₂)₂), 3.15 (s, 2×CH₃), 3.35-3.50(m, CH₂)₃), 3.52-3.62 (CH₂), 3.63-3.73 (m, (OCH₂CH₂)_(n)), 4.00 (m,CH₂), 5.34 (m, (CH═CH), 7.84 (s, NH). ¹³C-NMR (125 MHz, CDCl₃, TMS) δ(ppm): 14.0, 22.6, 23.5, 26.0, 27.1, 29.2, 29.4, 29.5, 29.6, 29.7, 31.8,35.7, 43.3, 50.8, 55.1, 62.1, 62.9, 68.8-71.5, 129.7, 129.8, 171.0 IR υ(cm⁻¹) 3406, 2924, 2856, 1647, 1466, 1349, 1290, 1097, 1037, 948.

Synthesis of Oleyl Polyoxyethylene Amidopropyl Hydroxy Sulfobetaine(OPAH)

The intermediate 4 (10.0 g, 12.76 mmol),3-chloro-2-hydroxypropanesulfonic acid sodium salt (1) (3.13 g, 15.94mmol), and sodium carbonate (1.35 g, 12.76 mmol) were dissolved inEthanol:water (72:24 mL) using 0.5 L 2-necked round bottom flask joinedwith a condenser. The pale yellow viscous material was obtained,filtered, washed with toluene after the reaction that was continued at85° C. for 12 hours. The viscous product was further purified usingcolumn chromatography. The column was filled with silica and ethanol wasused as a mobile phase to afford surfactant OPAH (See N. Parris, J.Well, W. Linfield, Soap-based detergent formulations: XII. Alternatesyntheses of surface active sulfobetaines, Journal of the American OilChemists' Society 53(2) (1976) 60-63; and X. F. Geng, X. Q. Hu, J. J.Xia, X. C. Jia, Synthesis and surface activities of a noveldi-hydroxyl-sulfate-betaine-type zwitterionic gemini surfactants,Applied surface science 271 (2013) 284-290, each incorporated herein byreference in their entirety) as a pale yellow viscous material. ¹H-NMR(500 MHz, CDCl₃, TMS) δ ppm. 0.87 (t, J=6.7 Hz, CH₃), 1.16-1.36 (m,(CH₂)_(n)), 1.51-1.61 (m, CH₂), 1.95-2.05 (m, (CH₂)₃), 3.22, (m, CH₂),3.21 (s, 2×CH₃), 3.45-3.55 (m, (CH₂)₂), 3.50-3.65 (m, (OCH₂CH₂)_(n)),4.00 (m, CH₂) 4.67 (m, CH), 5.34 (m, CH═CH), 7.97 (s, NH). ¹³C-NMR(chloroform-d, 125 MHz) δ (ppm): 14.0, 22.5, 25.9, 27.1, 29.2, 29.4,29.5, 29.6, 29.7, 31.8, 35.8, 51.8, 55.3, 62.9, 63.5, 68.5-71.4, 129.7,129.8, 171.2. IR υ (cm⁻¹) 3404, 2923, 2855, 1647, 1458, 1349, 1297,1097, 1041, 948.

Results and Discussion

The synthesis of OPAC, OPAS, and OPAH is depicted in FIG. 10 [Y. Wang,Y. Zhang, X. Liu, J. Wang, L. Wei, Y. Feng, Effect of a Hydrophilic HeadGroup on Krafft Temperature, Surface Activities and RheologicalBehaviors of Erucyl Amidobetaines, J. Surfactants. Deterg. 17(2) (2014)295-301; Z. Chu, Y. Feng, A facile route towards the preparation ofultra-long-chain amidosulfobetaine surfactants, Synlett 2009(16) (2009)2655-2658; each incorporated herein by reference in their entirety].3-(dimethylamino)-1-propylamine (5) was treated with glycolic acidethoxylate oleyl ether (6) (average Mn ˜700) using sodium fluoride as acatalyst at 160° C. to acquired intermediate (4). The intermediate (4)was then separately treated with sodium chloroacetate (3),1,3-propanesultone (2), and 3-chloro-2-hydroxypropanesulfonic acidsodium salt (1) to form the corresponding OPAC, OPAS, and OPAH,respectively.

Structure Elucidation

The structures of all synthesized material, as well as intermediate,were confirmed using FTIR and NMR (proton, carbon-13) spectrophotometer.The structure confirmation of OPAS is presented here for example.According to proton NMR spectra of OPAS (FIG. 1 ), the peaks at δ 0.88and δ 1.17-1.37 could be linked to CH₃ and CH₂ groups [(CH ₃—(CH₂)_(n)—] in the hydrophobic tail of OPAS respectively. The CH₃ groups ofquaternary ammonium headgroup [—CH₂—N—(CH₃)₂—CH₂—] could be associatedwith the singlet peak resonated at δ 3.15. The CH₂ groups of ethoxyunits (—CH ₂—CH ₂—O—CH ₂—CH ₂—O—) could be related to overlapped peaksdetected at δ 3.62-3.72. The peak of 2 protons at δ 5.34 could becoupled with the internal olefin (—CH₂—CH═CH—CH₂—) of surfactant tail.The amide N—H could be referred to the peak of 1 proton at δ 7.84.According to carbon-13 NMR spectra of OPAS (FIG. 2 ), the peaks at δ14.0 and 22.6-35.7 could be coupled with the CH₃ and CH₂ groups[(CH₃—(CH₂)_(n)-] in the hydrophobic tail of OPAS. The CH₃ groups ofquaternary ammonium headgroup [—CH₂—N—(CH₃)₂—CH₂-] could be associatedwith the peak resonated at δ 50.8. The CH₂ groups connected withammonium headgroup [—CH₂—N—(CH₃)₂—CH₂-] could be linked with the peakobserved at δ 62.1 and δ 62.9. The CH₂ groups of ethoxy units(—CH₂—CH₂—O—CH₂—CH₂—O—) could be related to overlapped peaks detected atδ 68.8-71.5. The two peaks observed at δ 129.7 and δ 129.8 could becoupled with the two carbons of internal olefin (—CH₂—CH═CH—CH₂—) ofsurfactant tail. The amide carbonyl (R—C═O—NH) could be referred to thepeak detected at δ 171.0. In FTIR spectra of OPAS (FIG. 3 ), the N—Hstretching and C═O stretching of amide functionality were detected at3406 cm⁻¹ and 1647 cm⁻¹ respectively. Asymmetric and symmetricstretching of a C—H band of hydrophobic tail of OPAS were resonated at2923 cm⁻¹ and 2855 cm⁻¹. Ether (C—O—C) stretching bands and C—H bendingvibration were identified at 1097 cm⁻¹ and 1466 cm⁻¹, respectively.Overall, FT-IR and NMR (proton, carbon-13) were matched with thestructure of OPAS.

Salt Tolerance

Solubility and stability of the surfactants at reservoir temperature andions are the major factors considered for its oilfield applications.Less soluble surfactants in FW and injected water (SW) are notconsidered for such kind of applications. Surfactants containing a longtail (≥C18) are not good candidates for oilfield applications owing tothe poor solubility in FW and SW. See S. Shakil Hussain, M. A.Animashaun, M. S. Kamal, N. Ullah, I. A. Hussein, A. S. Sultan,Synthesis, characterization and surface properties of amidosulfobetainesurfactants bearing odd-number hydrophobic tail, Journal of Surfactantsand Detergents 19(2) (2016) 413-420, incorporated herein by reference inits entirety. However, proper adjustment of EO groups within thesurfactant structure can enhance the solubility through hydrogenbonding. This hydrogen bonding takes place between the hydrogen of waterand oxygen of ethoxy group. See C. Negin, S. Ali, Q. Xie, Most commonsurfactants employed in chemical enhanced oil recovery, Petroleum 3(2)(2017) 197-211, incorporated herein by reference in its entirety. Thesolubility and salt tolerance experiments of OPAC, OPAS, and OPAH weredone at 90° C. for 90 days in FW, SW, and DW. All surfactants (OPAC,OPAS, and OPAH) showed excellent solubility in FW, SW, and DW and noapparent insoluble surfactants were detected. The solutions of OPAC,OPAS, and OPAH in FW, SW, and DW remained transparent for 90 days at 90°C. and no precipitation or phase separation was detected (FIGS. 4 and 5)which demonstrated excellent solubility and salt tolerance of thesynthesized OPAC, OPAS, and OPAH.

Thermal Stability

Thermal stability of any injected chemical at reservoir conditions isthe prerequisite for its oilfield application. The residence time forsurfactants in oil reservoir is very long and the high temperature ofoil reservoir (≥90° C.) can lead to surfactant decomposition. The heatstabilities of the OPAC, OPAS, and OPAH surfactants were studied usingTGA analysis. According to TGA data (FIG. 6 ), all three surfactants(OPAC, OPAS, and OPAH) found to be stable almost up to 300° C. Theinitial loss in weight was 30%, 29%, and 25% for OPAC, OPAH, and OPAS,respectively. This weight loss is associated with the water and solvent.The big weight loss was noticed at 312° C., 307° C., and 295° C. forOPAC, OPAH, and OPAS respectively which is quite higher than theexisting oilfield temperatures (≥90° C.).

Surface Tension

The surface properties of the synthesized surfactants were analyzed at30° C. and 60° C. and the data is presented in FIGS. 7-9 and summarizedin Table 2. The surface tension data was further used to determine othersurface properties such as cmc. The surface tension of OPAC, OPAS, andOPAH showed similar behavior by varying temperature and concentration.The reduction in surface tension was noticed upon increasing surfactantconcentration until the breakpoint which is also called cmc. At higherconcentrations (>cmc), the change in surface tension associated withsurfactant concentration was negligible. The surface tension reduced byincreasing the temperature and this behavior was noted for allsurfactants. The surface tension reduction caused by temperature wasrelated to a reduction in hydrophilic nature of surfactant because ofhydrogen bond breading. See G. H. Sayed, F. M. Ghuiba, M. I. Abdou, E.A. A. Badr, S. M. Tawfik, N. A. M. Negm, Synthesis, surface,thermodynamic properties of some biodegradable vanillin-modifiedpolyoxyethylene surfactants, Journal of Surfactants and Detergents 15(6)(2012) 735-743; and L.-J. Chen, S.-Y. Lin, C.-C. Huang, E.-M. Chen,Temperature dependence of critical micelle concentration ofpolyoxyethylenated non-ionic surfactants, Colloids and Surfaces A:Physicochemical and Engineering Aspects 135(1-3) (1998) 175-181, eachincorporated herein by reference in their entirety.

Hydrogen bond breaking may result in separation of surfactant moleculefrom the water phase and adsorb at the interface which promotesmicellization and results in a decrease of surface tension. The cmc andsurface tension at cmc (γ_(cmc)) reduced upon increasing temperature forall surfactants (OPAC, OPAS, and OPAH). The change in the head group ofthe surfactants also affect the surface properties. The maximum cmc(3.46×10⁻⁴) was noted for the surfactant-containing carboxylateheadgroup (OPAC). The surfactant-containing hydroxy sulfonate headgroup(OPAH) showed the least cmc (3.35×10⁻⁵ mol L⁻¹). Similarly, thesurfactant-containing sulfonate headgroup (OPAS) showed the highestγ_(emo) while the OPAC showed the least γ_(cmc). The cmc and γ_(cmc) ofOPAS and OPAH are closer to each other compared to the OPAC. The π_(cmc)value increased by increasing the temperature and maximum π_(cmc) wasobserved by using OPAC which suggests that the OPAC has more capabilityto reduce the surface tension but at comparatively higher concentrationis required due to high cmc. The maximum surface excess (Γ_(max), molesat the interface per unit area) of all surfactants decreased withtemperature, however, OPAC showed the least value of maximum surfaceaccess at both temperatures (30° C. and 60° C.). The minimum surfacearea per molecule also changes by changing the headgroup andtemperature. The minimum area per molecules (A_(min)) slightly increasedby increasing the temperature and OPAC showed maximum surface area permolecule. Thus, the surface properties data indicates that the surfaceproperties change with temperature and by varying the head group.

TABLE 2 Surface properties of OPAC, OPAS, and OPAH T cmc γ_(cmc) π_(cmc)Γ_(max) × 10⁶ A_(min) Surfactant (° C.) (mol L⁻¹) (mN m⁻¹) (mN/m) (molm⁻²) (nm²) OPAC 30 3.46 × 10⁻⁴ 34.67 37.33 1.70 0.97 OPAC 60 9.70 × 10⁻⁵32.24 39.76 1.58 1.04 OPAH 30 7.10 × 10⁻⁵ 36.89 34.96 2.66 0.62 OPAH 603.35 × 10⁻⁵ 33.68 38.07 2.33 0.71 OPAS 30 3.66 × 10⁻⁵ 37.04 35.59 2.150.77 OPAS 60 3.41 × 10⁻⁵ 33.74 38.26 1.64 1.01

Therefore, zwitterionic surfactants containing EO units and anunsaturated tail possess excellent solubility in oilfield water and highheat stability. Various ionic headgroups influence the surface andthermal behavior of betaine-based surfactants. All three surfactants(OPAC, OPAS, and OPAH) were found to be soluble in simulated SW, and FWand no apparent insoluble surfactants were observed up to 90 days at 90°C. The presence of EO units increase the hydrophilicity of thesynthesized surfactants and makes them more soluble in high salinitybrine. The TGA graph showed excellent heat stability and thedecomposition temperatures of the surfactants were in the order of OPAC(312° C.)>OPAH (307° C.>OPAS (295° C.) which is higher than the actualoilfield temperature (≥90° C.). TGA results revealed that the nature ofhead group has tiny effect on the thermal stabilities. The cmc values ofOPAC, OPAS, and OPAH were reduced upon enhancing the temperature byfollowing the order OPAH<OPAS<OPAC. The high CMC value of OPAC may bedue to the high hydrophilicity of the molecule. The OPAC has onemethylene group between positive and negative ion pair of the moleculewhich make it more hydrophilic. Moreover, OPAH with extra hydroxy grouphas slightly lower CMC than OPAS and OPAC due to decrease in repulsionbetween ionic head groups leading to a lower CMC. Similarly, the γ_(cmc)values of OPAC, OPAS, and OPAH also decreased by increasing temperatureand the order of reduction was OPAC<OPAH<OPAS. However, the change inthe γ_(cmc) values with temperature was not significant. Thezwitterionic surfactants containing EO units and unsaturated tail showedsuperior properties such as great salt tolerance, outstanding thermalstability, and higher surface characteristics which make them anappropriate candidate for severe reservoir conditions.

The invention claimed is:
 1. A method of fracking a subterraneangeologic formation, comprising: injecting an oil and gas well servicingfluid into an oil and gas well in the subterranean geologic formation,wherein the injecting is at a pressure above the fracture point of thesubterranean geologic formation; wherein the oil and gas well servicingfluid comprises: an aqueous base fluid; and a surfactant of formula (I)

wherein: each of R₁ and R₂ are independently H or an optionallysubstituted C₁ to C₆ alkyl, R₃ and R₄ are independently an optionallysubstituted C₁ to C₆ alkyl; x is 6; y is an integer in a range of from 7to 10; z is 6; n is an integer in a range of from 3 to 4; A is ananionic headgroup selected from the group consisting of

wherein the oil and gas well servicing fluid has a total dissolvedsolids content in a range of from 50,000 to 350,000 ppm, wherein thesurfactant is present in a range of from 0.045 to 2 wt. %, relative to atotal weight of the oil and gas well servicing fluid, wherein thesurfactant has a number average molecular weight in a range of from 600to 1200 g/mol, and wherein, during the injecting, the surfactant has aconcentration in a range of from 3×10⁻⁵ to 5×10⁻⁴ M.
 2. The method ofclaim 1, wherein each of R₁ and R₂ are independently a hydrogen, or amethyl.
 3. The method of claim 1, wherein each of R₁ and R₂ are ahydrogen.
 4. The method of claim 1, wherein R₃ and R₄ are independentlyselected from the group consisting of a methyl, an ethyl, and anisopropyl.
 5. The method of claim 1, wherein R₃ and R₄ are a methyl. 6.The method of claim 1, wherein y is
 8. 7. The method of claim 1, whereiny is
 9. 8. The method of claim 1, wherein n is
 3. 9. The method of claim1, wherein A is


10. The method of claim 1, wherein A is


11. The method of claim 1, wherein A is


12. The method of claim 1, wherein the carbon-carbon double bond presentin formula (I) is in a cis-double bond configuration.
 13. The method ofclaim 1, wherein the surfactant is selected from the group consisting of

wherein in each structure y is 8 or
 9. 14. The method of claim 1,wherein the surfactant is present in a range of from 0.05 to 0.1 wt. %relative to a total weight of the oil and gas well servicing fluid. 15.The method of claim 1, wherein the subterranean geologic formation has atemperature in a range of from 30 to 150° C.